Digital underreamer

ABSTRACT

Wellbore drilling apparatus and methods are provided. The apparatus includes a reaming subassembly including one or more reamers configured to ream a wellbore. The reaming subassembly defines a cutting aggressiveness that is variable while the reaming subassembly is disposed in a wellbore. The apparatus also includes an actuator coupled with the reaming subassembly and configured to vary the cutting aggressiveness of the reaming subassembly in response to an actuation signal.

BACKGROUND

Wellbores can be formed using a two step process whereby a pilot hole can be initially drilled using a drill bit and then radially expanded or “reamed” using a reamer. In some cases, multiple reamers can be used to ream the hole to a target diameter, step-wise, or one pass with a single reamer can be sufficient. This two-step process (drilling and reaming) can be employed for safety or efficiency reasons, or both. Further, the two steps can be performed by a single bottom hole assembly (BHA), such that the BHA both drills and reams the pilot hole in a single pass, as part of a process known as “reaming while drilling” (RWD).

RWD applications include underreaming. In underreaming, the BHA passes through a reduced diameter section of the wellbore and then the reamer can be radially expanded and employed to provide an enlarged diameter section. Underreaming can be used, for example, to provide sufficient annular space for a casing liner, or for any other reason. Typically, the reamer can be initially retracted and held close to the tubular body of the BHA for passage through the aforementioned reduced diameter section. Once the reamer reaches the desired depth, it can be mechanically actuated, for example, hydraulically or by using a drop ball, causing arms of the reamer to expand outward and engage the formation.

One challenge experienced in RWD applications can be a disparity between the rate of penetration of the reamer and the rate of penetration of the drill bit. This challenge can be caused by the BHA extending across a boundary or transition between one formation layer and a subjacent formation layer, where the two layers have different hardnesses. This can be seen in offshore drilling, for example, where a layer of sand can be subjacent to a layer of salt, or vice versa. When the rock hardness is greater at the reamer than at the drill bit, the weight on the reamer (WOR) during drilling operations can increase, while the weight on the drill bit (WOB) can decrease. Further, the torque on the reamer (TOR) also increases, while the torque on the bit (TOB) decreases.

The overall rate of penetration can be sensitive to the rock hardness at both the drill bit and the reamer. Accordingly, if the drill bit proceeds from a harder region into a softer region, while the reamer remains in the harder region, the rate of penetration of the BHA (including both bit and reamer) will be limited by the reamer rate of penetration, with little or no indication topside that the torque and weight on the reamer have increased, potentially causing vibration of the bit and excessive load on the reamer. In the reverse situation, increased rock hardness at the drill bit, as compared to the rock hardness at the reamer, can result in undesired vibration and can slow the overall rate of penetration.

What is needed are systems and methods for reducing vibration in multi-layer RWD operations.

BRIEF SUMMARY

Various aspects of the disclosure can provide a drilling assembly which can be particularly useful in multi-layer drilling applications, for example. The drilling assembly can be, be part of, or include a bottom hole assembly, and can include a drill bit and a reaming subassembly having one or more reamers. One or more sensors, such as single-axis or multi-axis vibration sensors, mechanical load sensors (e.g., strain gauges, torque sensors, etc.), sonic sensors, or the like can be positioned in or proximal to the drilling assembly, and can provide information to a controller indicating when the mechanical load (e.g., weight and/or torque) on the reaming subassembly is different from the mechanical load on the drill bit. The reaming subassembly, in turn, can have a variable cutting aggressiveness, which can be modulated by an actuator in response to signals sent by the controller. The controller can thus determine when the mechanical load on the reaming subassembly is disproportionate to the mechanical load on the drill bit, and then modulate the cutting aggressiveness of the reaming subassembly accordingly.

Modulating the cutting aggressiveness of the reaming subassembly can be accomplished in a variety of ways according to the present disclosure, such as by retracting one reamer of the reaming subassembly and expanding another reamer, with the two reamers having different cutting aggressiveness levels. Another way can be to vary the cutting aggressiveness of a single (or each) reamer, for example, by changing the back rake angle and/or cutting depth thereof. In some instances, a combination of these cutting-aggressiveness-varying structures can be provided in a single reamer or in a single reaming subassembly.

Embodiments of the disclosure can provide a wellbore drilling apparatus. The apparatus can include a reaming subassembly including one or more reamers configured to ream a wellbore. The reaming subassembly can define a cutting aggressiveness that is variable while the reaming subassembly is disposed in a wellbore. The apparatus can also include an actuator coupled with the reaming subassembly and configured to vary the cutting aggressiveness of the reaming subassembly in response to an actuation signal.

Embodiments of the disclosure can also provide a method for reaming while drilling. The method can include drilling a pilot hole for a wellbore with a drill bit of a drilling assembly, and reaming the pilot hole with a reaming subassembly of the drilling assembly. The method can also include detecting, using a sensor, that a mechanical load on the reaming subassembly is disproportionate to a mechanical load on the drill bit. The method can also include, in response to detecting that the mechanical load on the reaming subassembly is disproportionate to the mechanical load on the drill bit, varying a cutting aggressiveness of the reaming subassembly while the reaming subassembly is disposed in the wellbore.

Embodiments of the disclosure can further provide a method for controlling a drilling assembly. The method can include determining that a mechanical load on a drill bit of the drilling assembly is disproportionate to a mechanical load on a reaming subassembly of the drilling assembly. The method can also include, in response, varying a cutting aggressiveness of the reaming subassembly while the drilling assembly remains in the wellbore.

Embodiments of the disclosure can also provide a drilling apparatus. The drilling apparatus can include a drilling assembly including a body having a proximal end coupled with a drill pipe and a distal end coupled with a drill bit, and a reaming subassembly coupled to the body between the proximal end and the distal end. The reaming subassembly can define a cutting aggressiveness that is variable while the drilling assembly is disposed in the wellbore. The drilling apparatus can also include a sensor configured to sense when a load on the drill bit is disproportionate to a load on the reaming subassembly. The drilling apparatus can further include a controller communicable with the drilling assembly and the sensor, with the controller configured to signal the drilling assembly to adjust the cutting aggressiveness of the reaming subassembly in response to data received from the sensor.

BRIEF DESCRIPTION OF THE DRAWINGS

Various features of the embodiments can be more fully appreciated, as the same become better understood with reference to the following detailed description of the embodiments when considered in connection with the accompanying figures, in which:

FIGS. 1A-1C illustrate schematic side views of a drilling assembly having a reaming subassembly including a first reamer and a second reamer, according to an embodiment.

FIGS. 2A and 2B illustrate partial schematic side views of a reamer having a variable back rake angle, according to an embodiment.

FIGS. 3A and 3B illustrate partial schematic side views of a reamer having a variable cutting depth, according to an embodiment.

FIG. 4 illustrates a flowchart of a method for reaming while drilling, according to an embodiment.

FIG. 5 illustrates a flowchart of a method for controlling a drilling assembly, according to an embodiment.

DETAILED DESCRIPTION

For simplicity and illustrative purposes, the principles of the present teachings are described by referring mainly to examples of various embodiments thereof. However, one of ordinary skill in the art would readily recognize that the same principles are equally applicable to, and can be implemented in, all types of information and systems, and that any such variations do not depart from the true spirit and scope of the present teachings. Moreover, in the following detailed description, references are made to the accompanying figures, which illustrate specific examples of various embodiments. Electrical, mechanical, logical and structural changes can be made to the examples of the various embodiments without departing from the spirit and scope of the present teachings. The following detailed description is, therefore, not to be taken in a limiting sense and the scope of the present teachings is defined by the appended claims and their equivalents.

FIG. 1A illustrates a drilling assembly 100 including a reaming subassembly 101 with a selectable or variable cutting aggressiveness, according to an embodiment of the disclosure. In some situations and/or applications, the drilling assembly 100 may be or form part of a bottom hole assembly. However, in other situations, the drilling assembly 100 may include a bottom hole assembly as well as other parts of a drill string or other components. The drilling assembly 100 can further include a body 102 having a proximal end 104 and a distal end 106. A drill bit 108 of the drilling assembly 100 can be coupled to the distal end 106 and can be any suitable type or size of drill bit. The reaming subassembly 101 can be coupled to the body 102 between proximal and distal ends 104, 106. A drill pipe 110 can be coupled to the proximal end 104. When the drilling assembly 100 is deployed, one or more such drill pipes 110 (e.g., a plurality of drill pipes 110 made-up, end-on-end) can form a drill string extending from the drilling assembly 100 to the surface (not shown) directly or via any other tubulars, devices, or other structures, as necessary.

The body 102 can be at least partially constructed of a rigid material, for example, a metal or metal alloy, and can thus be configured to rotate at a constant rate from the proximal end 104 to the distal end 106. In other embodiments, however, the body 102 can be segmented or otherwise constructed such that one portion of the body 102 can be rotatable at a different rate than another portion, for example, by provision of a mud motor, electrical motor, or another type of rotation-inducing device.

The reaming subassembly 101 can include a plurality of reamers, for example, a first reamer 112 and a second reamer 114. The first and second reamers 112, 114 can be axially offset and concentric, although eccentric reamers 112, 114 can instead or additionally be employed. The first and second reamers 112, 114 can each include a plurality of cutting arms 116, 118, respectively, and the first and second reamers 112, 114 can each have a cutting aggressiveness at which the first and second reamers 112, 114 can be configured to cut into a formation. The orientation, cutting depth, number of cutters, size of cutters, back rake angle, and number of blades, among other possible factors, of the cutting arms 116, 118 can determine the cutting aggressiveness at which the first and second reamers 112, 114 can be configured to attack the formation.

As the term is used herein, “cutting aggressiveness” generally refers to the relationship between the amount of weight on bit (WOB) or weight on reamer (WOR) and the amount of torque on bit (TOB) or torque on reamer (TOR), respectively, generated thereby. That is, a high cutting aggressiveness means relatively less weight on the drilling member (bit or reamer) is required to generate a certain torque, while a low cutting aggressiveness means a relatively large amount of weight on the drilling member is required to generate the same torque. Moreover, without being limited by theory and taking into consideration reasonable uncertainty, if the rate of revolution (RPM), cutting efficiency, and the weight on the cutting member are known, then the rate of penetration (ROP) of the cutting member can be a function of the proportional to the cutting aggressiveness and inversely proportional to the hardness of the rock in which the cutting member is disposed.

Returning to FIG. 1A, the cutting aggressiveness of the first reamer 112 can be different from the cutting aggressiveness of the second reamer 114. For example, the first reamer 112 can have a lesser cutting aggressiveness than the second reamer 114. However, in other embodiments, the reverse can be true and the first reamer 112 can have a greater cutting aggressiveness than the second reamer 114.

Further, the reamers 112, 114 can be actuated between an expanded position (as shown) and a retracted position. In the expanded position, the reamers 112, 114 can be configured to engage and cut into a formation when the drilling assembly 100 is deployed. In the retracted position, the cutting arms 116, 118 of the retracted reamer 112 and/or 114 can be drawn radially inward, for example, to a position at or inside of the outer diameter of the body 102. Accordingly, in the retracted position, the reamer 112 and/or 114 can avoid engaging the formation. In some embodiments, a sleeve, cover, or any other suitable structure, can cover the cutting arms 116, 118 when the associated reamer 112, 114 is in the retracted position; however, in other embodiments, the sleeve can be omitted.

The drilling assembly 100 can also include a sensor 120 and/or an actuator 122, of which either or both can be communicable with a controller 124. The controller 124 can be located remotely from the drilling assembly 100, for example, at a surface of the wellbore, or can be disposed proximal to the drilling assembly 100 or therein. The controller 124 can be any suitable programmable logic controller and can form part of a measuring-while-drilling (MWD) system and/or a logging-while-drilling (LWD) system. Further, the controller 124 and can provide and/or be integrated with a user interface for an operator to monitor, control, and/or override the controller 124 logic, for example, in the event of an emergency. In other embodiments, the controller 124 can be located within or proximal to the drilling assembly 100 and can be self-contained and autonomous.

A battery 126 can be provided to power at least the actuator 122 and/or the vibration sensor 120, and can be any suitable type of battery configured for use over a period of hours, days, weeks or more. A variety of suitable batteries is known and can be employed consistent with the present disclosure. In some embodiments, in addition to or in lieu of the battery 126, a power line can be run from an external, topside power source, through the drill string 110 to the actuator 122 and/or the vibration sensor 120 to provide power thereto.

Further, the actuator 122 can be coupled to one or more valves, and can provide actuation of the reaming subassembly 101 by modulating a position of one or more of the valves. Such valve modulation can control one or more flows of hydraulic fluids (e.g., drilling fluids), pneumatics, or the like, such that a relatively small amount of power can be supplied to the actuator 122 to control comparatively large forces to provide actuation (e.g., extension and/or retraction of the reamers 112, 114) of the reaming subassembly 101. In other embodiments, the actuator 122 can be a servomotor, solenoid, or other electromechanical device configured to directly actuate the reaming subassembly 101.

A variety of suitable sensors 120 are also known and can be employed consistent with the present disclosure. For example, the sensor 120 can be a vibration sensor, including one or more, for example, three, accelerometers, one disposed in each axis for which vibration information is desired. Such accelerometers can be disposed in a ruggedized and/or stabilized housing for deployment with and/or within the drill string 110 and/or the drilling assembly 100. In other embodiments, the sensor 120 can be a mechanical load sensor, such as a strain gauge or torque sensor, configured to directly measure load on the body 102, the drill bit 108, or any other relevant structure. The mechanical load sensor can be configured to measure compressive forces, tensile forces, and/or torque forces.

In yet other embodiments, the sensor 120 can be a formation evaluation sensor or a logging sensor (e.g., a sonic sensor), configured to measure one or more formation rock properties, such as rock hardness. As noted above, and still not being bound by theory, knowledge of rock hardness and cutting aggressiveness can allow a calculation of the mechanical load (i.e., weight and/or torque) on the reaming subassembly 101, the mechanical load on the drill bit 108, or both. Various other sensors are known and may be employed by one with skill in the art consistent with the present disclosure.

Furthermore, the sensor 120 may be disposed within any area of the drilling assembly 100. For example, the sensor 120 may be disposed within the drill bit 108, so as to sense data specific thereto (e.g., mechanical load on the drill bit 108, vibration, and/or rock hardness, etc.). In another embodiment, the sensor 120 can be disposed in the body 102 proximal the reaming subassembly 101, so as to sense data specific thereto. In yet another embodiment, the sensor 120 can be disposed in the drill pipe 110, above the drilling assembly 100. Moreover, it will be appreciated that multiple sensors 120 in any one or a combination of the aforementioned locations, and/or any other suitable location, may be employed consistent with the present disclosure.

The actuator 122 and/or the sensor 120 can be configured to communicate with the controller 124 via any suitable method. For example, wireless telemetry, acoustic signaling, electrical signaling, etc. can be employed to convey signals between the sensor 120 and the controller 124 and/or between the controller 124 and the actuator 122. For example, or one or more wires can be disposed in and extend at least partially in or along the drill string 110 to convey electrical signals between the sensor 120 and the controller 124 and between the controller 124 and the actuator 122, at least.

Although two reamers 112, 114 are illustrated, it will be appreciated that the reaming subassembly 101 can include one, two, three, or more reamers. Each reamer can have a unique cutting aggressiveness, or two or more of the reamers can share a common cutting aggressiveness. Additionally, the relative cutting aggressiveness among the reamers can proceed in any pattern, for example, increasing proceeding distally, decreasing proceeding distally, or can be distributed according to any or no pattern. Further, the reamers 112, 114 (and any others) can be configured to act independently and/or can be configured to work in tandem or in groups to arrive at a desired wellbore diameter.

FIGS. 1B and 1C schematically illustrate an example of operation of the drilling assembly 100 in a wellbore 128, according to an embodiment. The wellbore 128 can extend through at least two formation layers, for example, an upper layer 130 and a lower layer 132, with a boundary 134 defined therebetween. In at least one application, the upper layer 130 can have a greater rock hardness (i.e., more load on a given cutting member is required to remove a given amount of rock) than the lower layer 132. As shown, during drilling operations, the drill bit 108 can cross the boundary 134 and, at least temporarily, engage the softer, lower layer 132 while the reaming subassembly 101 can remain surrounded by the harder, upper layer 130.

Prior to the drill bit 108 crossing the boundary 134, one or both reamers 112, 114 can be expanded radially outward to ream the wellbore 128, or a third reamer (not shown) can perform the reaming while the first and second reamers 112, 114 are retracted. For purposes of illustration, FIG. 1B shows the first reamer 112 being expanded initially. When the drill bit 108 crosses into the softer lower layer 132, as shown in FIG. 1A, the mechanical load on the drill bit 108 can decrease. The reaming subassembly 101, however, which can still be in the harder upper layer 130, can thus be required to bear greater mechanical load, as it limits the rate of progression of the drill bit 108 through the softer lower layer 132. Relatedly, this can result in a reduced load on the drill bit 108, and a greater load on the reaming subassembly 101.

With the drill bit 108 bearing less mechanical load and the reaming subassembly 101 bearing greater mechanical load than would be the case if both the drill bit 108 and the reaming subassembly 101 were cutting through rock with substantially the same hardness, the mechanical load on the drill bit 108 and the mechanical load on the reaming subassembly 101 can be characterized as “disproportionate.” In some cases, the mechanical load on the drill bit 108 and the mechanical load on the reaming subassembly 101 can be the same when both are cutting through rock of substantially the same hardness, such that “disproportionate” is synonymous “different.” However, this is not necessarily the case, as some drilling assemblies 100 can be configured such that the mechanical load on the drill bit 108 and the mechanical load on the reaming subassembly 101 can be different, even when both are cutting through rock of the same hardness.

The mechanical load on the bit 108 and/or the mechanical load on the reaming subassembly 101 can also be directly measured, as with a mechanical load sensor 120. In some instances, only one such measurement can be required, with the total mechanical load on the drill string being a known value (e.g., taking into consideration friction between the drill string and the wellbore). In other embodiments, mechanical load measurements may be desired at both the drill bit 108 and the reaming subassembly 101 for increased accuracy and precision. In yet other embodiments, mechanical load on the drilling assembly in total can be measured, and compared with measurements of the mechanical load on either or both of the reaming subassembly 101 and the drill bit 108.

In some cases, formation rock hardness or other formation properties, e.g., at the drill bit 108, may be monitored by a sonic sensor 120. Increased rock hardness at the drill bit 108 may be one way to determine, or at least estimate, that the mechanical load on the reaming assembly 101 is disproportionately high as compared to the mechanical load on the drill bit 108.

Axial vibration in and/or proximal to the drilling assembly 100 can also be symptomatic of such disproportionate mechanical load on the reaming subassembly 101 and/or reduced mechanical load on the drill bit 108. Further, a combined lateral and axial vibration can be indicative of there being little or substantially no mechanical load on the drill bit 108, with substantially all mechanical load on the reaming subassembly 101, and may be symptomatic of impending overload and/or component failure.

The sensor 120 can detect such disproportionate mechanical loads on the reaming subassembly 101 and the drill bit 108, and relay a signal indicative thereof to the controller 124. The controller 124 can interpret the signal and determine when to modulate or vary the cutting aggressiveness of the reaming subassembly 101, or can display the vibration information to an operator and solicit the input of the operator, or both. Accordingly, upon a determination to vary the cutting aggressiveness of the reaming subassembly 101, the controller 124 can signal the actuator 122 to actuate the reaming subassembly 101. The actuator 122 can, in turn, adjust the reaming subassembly 101, for example, by retracting one of the reamers 112, 114.

In the embodiment illustrated in FIGS. 1B and 1C, the first, less aggressive reamer 112 can initially be expanded (FIG. 1B) and, upon actuation, can be retracted, while the second, more aggressive reamer 114 can be expanded (FIG. 1C). With the more aggressive second reamer 114 engaged, the same amount of mechanical load on the reaming subassembly 101 can result in a greater rate of penetration of the reaming subassembly 101 and thus the drilling assembly 100 (since the reaming subassembly 101 in this instance can act as the limiter on the rate of penetration of the drilling assembly 100). Accordingly, the appropriate amount of mechanical load on the reaming subassembly 101 can shift back to the drill bit 108. This can reduce disproportionate loads, vibrations, and potentially avoid overloading the reaming subassembly 101. Additionally, the actuator 122 and/or the sensor 120 can provide feedback to the controller 124, indicating whether the actuation was successful and/or whether further action, or repair in case of an unsuccessful actuation, can be required.

In another embodiment, the lower layer 132 can be the harder layer, while the upper layer 130 can be the softer layer, and the first reamer 112 can be the less aggressive reamer while the second reamer 114 can be the more aggressive reamer. Accordingly, when the drill bit 108 crosses into the lower layer 132, as shown in FIG. 1B, the mechanical load on the drill bit 108 can increase, while the mechanical load on the reaming subassembly 101 can decrease. As such, the mechanical load on the reaming subassembly 101 can again be disproportionate to the mechanical load on the drill bit 108, but in this case, disproportionately low with respect thereto.

Such disproportionate mechanical loading can be determined using the sensor 120, for example, by detecting formation rock hardness, vibration, or by direct detection of mechanical loading of the reaming subassembly 101, the drill bit 108, the drill pipe 110, combinations thereof, or the like, e.g., as generally described above. The sensor 120 can relay signals indicative of such disproportionate mechanical load distribution to the controller 124. The controller 124 can determine or solicit an operator's determination of when to take corrective action to attenuate such vibration and/or disproportionate mechanical loading. Upon such determination, the controller 124 can signal the actuator 122 to toggle from the less aggressive first reamer 112 to the more aggressive reamer 114. Accordingly, the actuator 122 can cause the cutting arms 116 of the first reamer 112 to retract, while the cutting arms 118 of the second reamer 114 can be expanded to engage the wellbore 128, as shown in FIG. 1C. As a result, the more aggressive, second reamer 114 can ream the softer, upper layer 130, such that the mechanical load on the second reamer 114 is increased, back into proportion with the mechanical load on the drill bit 108 in the harder, lower layer 132.

In addition to extending/retracting the reamers 112, 114, one or more of the reamers 112, 114 can have a variable cutting aggressiveness, as described below with reference to FIGS. 2A and 2B and/or FIGS. 3A and 3B. Accordingly, the reamers 112, 114 can have a range of selectable cutting aggressiveness levels, with the cutting aggressiveness ranges being either overlapping or discrete. This can allow for a greater number of cutting aggressiveness levels to be selectable within the reaming subassembly 101. For example, adjusting the cutting aggressiveness of the first reamer 112 or the second reamer 114 can provide a “fine” adjustment, while retracting one of the reamers 112, 114 and expanding the other can provide a “rough” adjustment, or vice versa.

FIGS. 2A and 2B schematically illustrate a partial side view of a reamer 200 having a variable cutting aggressiveness, according to an embodiment. Although not shown, the reamer 200 can be or form part of a reaming subassembly that can be incorporated into a drilling assembly (e.g., bottom hole assembly) of a drill string. The reamer 200 can include at least one cutting arm 202 and a body 204. The cutting arm 202 can extend radially outward from the body 204. In various embodiments, the cutting arm 202 can be pivotally coupled with the body 204 and configured to pivot about one, two, or more axis with respect thereto. For example, the cutting arm 202 can pivot from approximately parallel to the body 204 toward perpendicular to the body 204 (although it can stop well short of perpendicular in some embodiments) and back, enabling the cutting arm 202 to be radially expandable and retractable. As such, the cutting arm 202 can be selectively engaged with a cutting surface 206, which can be a ledge of a subterranean formation. Such pivotal retraction and extension can be provided via hydraulics, pneumatics, a motor, a drop ball, or any other device.

The cutting arm 202 can also be pivotal about an axis perpendicular to body 204. In at least one embodiment, the cutting arm 202 can have a circular cross section, defining a diametral reference line 208. The cutting arm 202 can be pivoted via an actuator, such that the diametral line 208 rotates with respect to the body 204 and the cutting surface 206, as can be appreciated by comparing the position of the line 208 in FIGS. 2A and 2B. The actuator can be similar to the actuator 122 shown in and described above with reference to FIGS. 1A-1C, and can be electromechanical and capable of modulating a valve position so as to hydraulically actuate the reamer 200, for example, pivot the cutting arm 202. In other embodiments, the actuator may actuate the reamer 200 via direct mechanical, magnetic, or electrical linkage, or may control a pneumatic assembly. Further, in an embodiment, the actuator can be disposed within the body 204 and can be communicable with a controller disposed at the surface or elsewhere. The controller can be similar to the controller 124 shown in and described above with reference to FIGS. 1A-1C and can be communicable with the actuator and/or sensors, such as the vibration sensor 120 (FIGS. 1A-1C).

Although the cutting arm 202 is illustrated with a circular cross-section, it will be appreciated that any other cross-section can be employed consistent with the present disclosure. For example, the cross-section of the cutting arm 202 can be semicircular, partially circular and partially linear, polygonal (e.g., three-sided, four-sided, five-sided, ten-sided, or more), or any other shape. In such non-circular embodiments, the reference line 208 can be any line fixed with respect to the cross-section of the cutting arm 202, so as to define its orientation.

The reamer 200 can also include one or more cutting elements 212 (e.g., blades) extending from the cutting arm 202. The cutting elements 212 can be integrally formed with the cutting arm 202 or can be coupled thereto using any desired assembly method or device including, for example, welding, brazing, dovetail fitting, fastening, combinations thereof, or the like. Further, the cutting element 212 can be any shape, for example, rectilinear, as shown, but can also be curved, or a combination of curved and rectilinear. The cutting elements 212 can be fixed with respect to the cutting arm 202 or can be configured to rotate or otherwise move with respect to the cutting arm 202. In an embodiment, pivoting the cutting arm 202 can cause the cutting element 212 to rotate by a proportional amount (e.g., over the same angle).

In one example of operation, when the reamer 200 is deployed, a cutting edge 210 of the cutting element 212 can engage the cutting surface 206. A weight can be applied axially and a torque applied rotationally on the body 204, causing the body 204 to rotate in the circumferential direction D, while the cutting element 212 can bite into the cutting surface 206 and remove portions thereof as the cutting element 212 moves with the body 204. The cutting arm 202 can be angled with respect to the cutting surface 206, and can thus define a back rake angle α between the cutting edge 210 and the cutting surface 206. When the back rake angle α is increased, the cutting aggressiveness with which the cutting element 212 attacks the cutting surface 206 can generally be reduced. Further, when the back rake angle α approaches zero, the cutting aggressiveness of the cutting element 212 can approach its maximum, and when the back rake angle α approaches 90 degrees, the cutting aggressiveness of the cutting element 212 can approach its minimum.

In situations where it is desirable to vary the cutting aggressiveness, such as shown in and described above with reference to FIGS. 1B and 1C, the cutting arm 202 can be pivoted to modulate the back rake angle α. Accordingly, the back rake angle α can be pivoted between two angles or across a range of angles, for example, between the smaller back rake angle α shown in FIG. 3A and the larger back rake angle α shown in FIG. 2B. Such pivoting can allow for a single reamer 200 to have two or more cutting aggressiveness configurations that can be selected by control of the actuator. For example, the reamer 200 can change from being more aggressive (FIG. 2A) to being less aggressive (FIG. 2B).

Although a single reamer 200 is shown, it will be appreciated that a single drill string and/or a single drilling assembly can include two, three, four, or more of such reamers. Additionally, a single drill string and/or a single drilling assembly can include one or more variable reamers, such as the reamer 200, and/or one or more other reamers. Moreover, although a single cutting arm 202 is shown, it will be appreciated that the reamer 200 can include two, three, or more cutting arms 202, disposed at equiangular or varying intervals, according to a variety of factors such as formation hardness, rate of penetration, or the like. Further, although a single cutting element 212 is shown, it will be appreciated that each cutting arm 202 can include two, three, or more cutting elements 212 as desired, each of which can be fixed blades, as schematically illustrated, or can be rotatable relative to the cutting arm 202.

Another way to vary cutting aggressiveness downhole can be to vary cutting depth. Accordingly, FIGS. 3A and 3B schematically illustrate a reamer 300 having a wear pad 301 moveable between an extended position (FIG. 3A) and a retracted position (FIG. 3B) so as to vary the cutting depth the reamer 300, according to an embodiment. Although not shown, the reamer 300 can be or form part of a reaming subassembly that can be incorporated into a drilling assembly of a drill string. The reamer 300 can include a body 302 and one or more cutting arms 304 extending radially outward therefrom. Although illustrated as having a circular cross section, it will again be appreciated that the cutting arm 304 can have any shape, to include multiple shapes at different cross-sectional locations along the cutting arm 304. The cutting arm 304 can be integral with the body 302 or can be coupled thereto, for example, by welding, brazing, dovetail fitting, fastening, combinations thereof, or the like. For example, the cutting arm 304 can be pivotally coupled to the body 302, such that the cutting arm 304 pivots about at least one axis relative to the body 302. In an embodiment, the cutting arm 304 can pivot from approximately parallel to the body 302 toward perpendicular to the body 302 and back, such that the cutting arm 304 can be selectively expandable to engage a cutting surface 306 and retractable so as to avoid engagement with the cutting surface 306. The cutting surface 306 can be a ledge of a subterranean formation.

A cutting element 308 (e.g., blade) can extend from the cutting arm 304 so as to engage and cut into the cutting surface 306. More particularly, the cutting element 308 can extend by a length L_(C). The length L_(C) can be determined according to a variety of factors, including the rock hardness, blade number and/or construction, back rake angle, desired maximum cutting aggressiveness, maximum cutting depth, and the like. Further, the length L_(C) that the cutting element 308 extends from the cutting arm 304 can be fixed. In other embodiments, the length L_(C) can be adjusted, for example, by coupling the cutting element 308 to an actuator (see, e.g., FIGS. 1A-1C) configured to extend or retract the cutting element 308. Furthermore, the cutting element 308 can be rotatable or pivotal with respect to the cutting arm 304, or can be non-pivotal or non-rotatable with respect thereto.

At least a portion of the body 302 can be configured to rotate in a circumferential direction D, such that the cutting element 308 also proceeds in the direction D relative to the cutting surface 306. As such, an application of torque and axial weight can cause the cutting element 308 to cut into the cutting surface 306.

Further, the one or more wear pads 301 can extend from the cutting arm 304 in approximately the same direction as the cutting element 308, i.e., toward the cutting surface 306, when the reamer 300 is deployed downhole. The wear pad 301 can be disposed circumferentially adjacent to the cutting element 308, i.e., the wear pad 301 can restrict the distance into the cutting surface 306 that the cutting element 308 can extend. More particularly, the wear pad 301 can extend length L_(W) from the cutting arm 304. The length L_(W) can be shorter than the length L_(C). The length L_(W) of the wear pad 301 can be varied, for example, by coupling the wear pad 301 to an actuator, such that the wear pad 301 can move between an extended position (FIG. 3A) and a retracted position (FIG. 3B). In other embodiments, for example, where the cutting elements 308 are extendable/retractable, the length L_(W) of the wear pad 301 can remain generally constant.

The wear pad 301 can be configured such that it does not substantially cut into the cutting surface 306, but rather slides across it. Accordingly, in an embodiment, the cutting depth, i.e., the depth into the cutting surface 306 that the cutting element 308 extends, can be limited to the difference between the length L_(C) of the cutting element 308 and the length L_(W) of the wear pad 301. This length differential can thus be referred to in the present embodiment as the cutting depth Δ.

During operation of the reamer 300, according to at least one embodiment, the wear pad 301 can be moved between the extended position (FIG. 3A) and the retracted position (FIG. 3B), or to any point in between, to vary the cutting aggressiveness of the reamer 300. As shown, the wear pad 301 can move orthogonally to the cutting surface 306, but in other embodiments, can extend radially from the cutting arm 304, with such radial extension being orthogonal to the cutting surface 306 or at an angle with respect thereto. In such a radially-extending embodiment, the change in length L_(W) can be a function (e.g., cosine) of the angle at which the wear pad 301 extends from the cutting arm 304. Such extension or retraction of the wear pad 301 while the length L_(C) of the cutting element 308 remains generally constant, can reduce or increase the cutting depth Δ, thereby varying the cutting aggressiveness of the reamer 300 correspondingly.

In other embodiments, the wear pad 301 can remain fixed, while the length L_(C) of the cutting element 308 can be varied. Such variation in the length L_(C) of the cutting element 308, with the wear pad 301 length L_(W) remaining generally constant, can also have the effect of varying the cutting depth Δ, with an increased length L_(W) resulting in an increased cutting depth Δ and thus an increased cutting aggressiveness. Moreover, in some embodiments, both the cutting element 308 and the wear pad 301 can be extendable and retractable, so as to allow for further modulation of the cutting depth Δ.

In general, it will be appreciated that the reamers 200 and 300 described above with reference to FIGS. 2A-3B can be employed with a drilling assembly including a drill bit so as to provide reaming-while-drilling functionality. Further, it will be appreciated that reamers including both pivotal cutting elements (such as the cutting elements 212 of FIGS. 2A and 2B) and extendable wear pads (such as the wear pads 301 of FIGS. 3A and 3B) are expressly contemplated and are not considered mutually exclusive unless otherwise stated herein. Furthermore, the drilling assembly 100 shown in and described above with reference to FIGS. 1A-1C and any elements thereof (including, without limitation, the actuator 122, sensor 120, and/or controller 124) can employ a single reamer including one or more aspects of either or both of the reamers 200 and/or 300, can include single or multiple instances of either or both of the reamers 200 and/or 300 and/or can include other reamers.

FIG. 4 illustrates a flowchart of a method 400 for reaming while drilling, according to an embodiment. The method 400 can proceed by operation of the reaming subassembly 101 and/or the reamers 200, 300 described above and can thus be best understood with reference thereto.

The method 400 can include drilling a pilot hole for a wellbore with a drill bit of a drilling assembly, as at 402. The method 400 can also include reaming the pilot hole with a reaming subassembly of the drilling assembly, as at 404. The method 400 can further include detecting a vibration and/or a mechanical load in the drilling assembly and/or one or more properties of the formation adjacent one or more portions of the drilling assembly, as at 406. The method 400 can also include varying a cutting aggressiveness of the reaming subassembly, as at 408, for example, when the mechanical load on the reaming subassembly is disproportionate (either high or low) with respect to the mechanical load on the drill bit. Such cutting aggressiveness variation can be achieved while the drilling assembly can be deployed in the wellbore, for example, by sending a signal (e.g., electrical, acoustic, pneumatic, hydraulic, etc.) to the drilling assembly.

In an embodiment, varying the cutting aggressiveness of the reaming subassembly, as at 408 can include sending the signal to an actuator of the drilling assembly, causing the actuator to actuate. Additionally, varying the cutting aggressiveness as at 408 can include retracting a first reamer of the reaming subassembly, with the first reamer having a first cutting aggressiveness, and expanding a second reamer of the reaming subassembly, with the second reamer having a second cutting aggressiveness that is different from the first cutting aggressiveness. Further, varying as at 408 can also include varying a back rake angle of a cutting element of the reaming subassembly, varying a cutting depth of a cutting element of the reaming subassembly, extending or retracting a wear pad, or a combination thereof. Further, the method 400 can include signaling whether the actuator successfully actuated. Additionally, the method 400 can include powering the actuator with a battery positioned proximal the drilling assembly.

FIG. 5 illustrates a flowchart of a method 500 for controlling a drilling assembly during drilling. The method 500 can proceed by operation of the drilling assembly 100, reaming subassembly 101, and/or the reamers 200, 300 described above and can thus be best understood with reference thereto. The method 500 can include determining that a mechanical load on a reaming assembly of the drilling assembly is disproportionate to a mechanical load on the drill bit of the drilling assembly, as at 502, and receiving a signal indicative thereof. Such determining can include measuring and comparing mechanical loads on various regions of the drilling assembly (e.g., on the drill bit, the reaming subassembly, and/or elsewhere). Further, such determining can include calculating a value or magnitude of such disproportionality, but in other embodiments can be a yes/no determination, without regard to a measurement or calculation of the magnitude of the disparity.

Such determining can additionally or instead include measuring axial vibration, lateral vibration, or both, formation rock hardness and/or other formation properties, for example, using a vibration, sonic, or another type of sensor located in or proximal to the drilling assembly. A controller can be provided to receive the signals via a wired and/or wireless connection.

The method 500 can also include providing a signal (e.g., electrical, acoustic, pneumatic, hydraulic, wireless, etc.) to the drilling assembly that causes the drilling assembly to alter a cutting aggressiveness of the reaming subassembly, as at 504. In an embodiment, providing the electrical signal that causes the drilling assembly to adjust a cutting aggressiveness of the reaming subassembly can include signaling an actuator disposed in the drilling assembly to actuate.

Providing the electrical signal at 504 can cause the cutting aggressiveness to alter in one or more ways. For example, the cutting aggressiveness can be altered by expanding a first reamer of the reaming subassembly and retracting a second reamer of the reaming subassembly. In another example, altering the cutting aggressiveness can proceed by adjusting a back rake angle of a reamer of the reaming subassembly. In yet another example, altering the cutting aggressiveness can proceed by adjusting a cutting depth of a reamer of the reaming subassembly. In some embodiments, combinations of these cutting aggressiveness alternations can be employed sequentially or simultaneously.

While the teachings have been described with reference to the embodiments thereof, those skilled in the art will be able to make various modifications to the described embodiments without departing from the true spirit and scope. The terms and descriptions used herein are set forth by way of illustration only and are not meant as limitations. In particular, although the method has been described by examples, the steps of the method may be performed in a different order than illustrated or simultaneously. Furthermore, to the extent that the terms “including”, “includes”, “having”, “has”, “with”, or variants thereof are used in either the detailed description and the claims, such terms are intended to be inclusive in a manner similar to the term “comprising.” As used herein, the terms “one or more of” and “at least one of” with respect to a listing of items such as, for example, A and B, means A alone, B alone, or A and B. Those skilled in the art will recognize that these and other variations are possible within the spirit and scope as defined in the following claims and their equivalents. 

What is claimed is:
 1. A wellbore drilling apparatus, comprising: a reaming subassembly comprising one or more reamers configured to ream a wellbore, the reaming subassembly defining a cutting aggressiveness that is variable while the reaming subassembly is disposed in a wellbore; and an actuator coupled with the reaming subassembly and configured to vary the cutting aggressiveness of the reaming subassembly in response to an actuation signal.
 2. The apparatus of claim 1, further comprising a controller communicable with the actuator and configured to send the actuation signal to the actuator.
 3. The apparatus of claim 2, wherein the controller is located remotely from the actuator.
 4. The apparatus of claim 2, further comprising a body coupled to the reaming subassembly and comprising a proximal end coupled with a drill pipe and a distal end coupled with a drill bit.
 5. The apparatus of claim 4, wherein the controller is communicable with the actuator through a wire extending at least partially along the drill pipe.
 6. The apparatus of claim 4, wherein the controller is communicable with the actuator via a wireless signal, an acoustic signal, an electrical signal, or a combination thereof.
 7. The apparatus of claim 4, further comprising one or more sensors configured to provide data to the controller indicative of whether a mechanical load on the reaming subassembly is disproportionate to a mechanical load on the drill bit.
 8. The apparatus of claim 7, wherein the one or more sensors comprise a mechanical load sensor, a vibration sensor, a formation evaluation sensor, or a combination thereof.
 9. The apparatus of claim 7, wherein the one or more sensors are located in the body and proximal the reaming subassembly, or in the drill bit, or in the drill pipe, or a combination thereof.
 10. The apparatus of claim 1, wherein the reaming subassembly comprises: a first reamer having a cutting aggressiveness; and a second reamer axially offset from the first reamer and having a greater cutting aggressiveness than the first reamer, wherein the actuator is configured to cause the first reamer to retract and the second reamer to expand, to increase the cutting aggressiveness of the reaming subassembly, and to cause the first reamer to expand and the second reamer to retract, to reduce the cutting aggressiveness of the reaming subassembly.
 11. The apparatus of claim 1, wherein the reaming subassembly comprises a cutting element pivotal over a range of back rake angles to vary the cutting aggressiveness of the reaming subassembly.
 12. The apparatus of claim 1, wherein the reaming subassembly includes a cutting element and a wear pad, the wear pad being configured to extend outward to reduce a cutting depth of the cutting element and to retract inward to increase the cutting depth of the cutting element.
 13. A method for reaming while drilling, comprising: drilling a pilot hole for a wellbore with a drill bit of a drilling assembly; reaming the pilot hole with a reaming subassembly of the drilling assembly; detecting, using a sensor, that a mechanical load on the reaming subassembly is disproportionate to a mechanical load on the drill bit; and in response to detecting that the mechanical load on the reaming subassembly is disproportionate to the mechanical load on the drill bit, varying a cutting aggressiveness of the reaming subassembly while the reaming subassembly is disposed in the wellbore.
 14. The method of claim 13, wherein varying the cutting aggressiveness comprises: receiving, using a controller, a signal from the sensor, the signal indicating that the mechanical load on the reaming subassembly is disproportionate to the mechanical load on the drill bit; sending an actuation signal from the controller to an actuator coupled with the reaming subassembly; receiving the actuation signal with the actuator; and in response to receiving the actuation signal, adjusting the reaming subassembly using the actuator.
 15. The method of claim 14, further comprising powering the actuator with a battery positioned proximal the drilling assembly.
 16. The method of claim 13, wherein varying the cutting aggressiveness of the reaming subassembly comprises: retracting a first reamer of the reaming subassembly, the first reamer having a first cutting aggressiveness; and expanding a second reamer of the reaming subassembly, the second reamer having a second cutting aggressiveness that is different from the first cutting aggressiveness.
 17. The method of claim 13, wherein varying the cutting aggressiveness of the reaming subassembly comprises varying a back rake angle of a cutting element of the reaming subassembly.
 18. The method of claim 13, wherein varying the cutting aggressiveness of the reaming subassembly comprises varying a cutting depth of a cutting element of the reaming subassembly.
 19. The method of claim 18, wherein varying the cutting depth of the cutting element comprises extending or retracting a wear pad.
 20. A method for controlling a drilling assembly, comprising: determining that a mechanical load on a drill bit of the drilling assembly is disproportionate to a mechanical load on a reaming subassembly of the drilling assembly; and in response, varying a cutting aggressiveness of the reaming subassembly while the drilling assembly remains in the wellbore.
 21. The method of claim 20, wherein varying the cutting aggressiveness of the reaming subassembly comprises: receiving a signal using an actuator coupled with the reaming subassembly; and in response to receiving the signal, adjusting the reaming subassembly using the actuator.
 22. The method of claim 21, wherein adjusting the reaming subassembly using the actuator comprises modulating one or more valves fluidly coupled with the reaming subassembly.
 23. The method of claim 20, wherein determining comprises detecting axial vibration, torsional vibration, lateral vibration, one or more formation rock properties, or a combination thereof.
 24. The method of claim 20, wherein determining comprises detecting a mechanical load on the reaming subassembly, the drill bit, or both.
 25. The method of claim 20, wherein varying the cutting aggressiveness comprises expanding a first reamer of the reaming subassembly and retracting a second reamer of the reaming subassembly to alter the cutting aggressiveness of the reaming subassembly.
 26. The method of claim 20, wherein varying the cutting aggressiveness comprises adjusting a back rake angle of a reamer of the reaming subassembly.
 27. The method of claim 20, wherein varying the cutting aggressiveness comprises adjusting a cutting depth of a reamer of the reaming subassembly.
 28. A drilling apparatus, comprising: a drilling assembly comprising a body having a proximal end coupled with a drill pipe and a distal end coupled with a drill bit, and a reaming subassembly coupled to the body between the proximal end and the distal end, wherein the reaming subassembly defines a cutting aggressiveness that is variable while the drilling assembly is disposed in the wellbore; a sensor configured to sense when a load on the drill bit is disproportionate to a load on the reaming subassembly; and a controller communicable with the drilling assembly and the sensor, the controller configured to signal the drilling assembly to adjust the cutting aggressiveness of the reaming subassembly in response to data received from the sensor.
 29. The drilling apparatus of claim 28, further comprising an actuator coupled with the reaming subassembly such that actuation of the actuator varies the cutting aggressiveness of the reaming subassembly, wherein the controller is communicable with the actuator.
 30. The drilling apparatus of claim 28, wherein the sensor is positioned in the drill bit.
 31. The drilling apparatus of claim 28, wherein the sensor is positioned in the body of the drilling assembly.
 32. The drilling apparatus of claim 31, wherein the sensor is positioned proximal the reaming subassembly.
 33. The drilling apparatus of claim 28, wherein the sensor is positioned in the drill pipe.
 34. The drilling apparatus of claim 28, wherein the sensor is a vibration sensor.
 35. The drilling apparatus of claim 28, wherein the sensor is a mechanical load sensor.
 36. The drilling apparatus of claim 28, wherein the sensor is a formation evaluation sensor, or a logging sensor, or a combination thereof, and is configured to measure one or more rock formation properties. 